A groundswell of interest in oil and gas production from shales is transforming the domestic industry. It's a surprising development for such an unassuming rock. After all, shales are the epitome of quiet-formed during eons of slow and steady deposition, undisturbed by great gushes of sediments from rivers or the busy, colorful lives of reef dwellers.

Shales are the tortoises among the world's hydrocarbon reservoirs, often under-appreciated and, until recently, often overlooked. But the rousing success of the Barnett shale play in the Fort Worth Basin, and the emergence of the Fayetteville and Woodford as powerhouses in the Arkoma Basin, have inspired evaluation of shale plays throughout the country.

The major lesson operators have learned in their fresh look at shales as reservoirs is that each play is unique. Many distinct characteristics work together in various combinations to yield commercial quantities of oil and gas. Target shales need certain geologic parameters, the correct drilling and completion technologies, and strong commodity prices to make economic sense.

And commercial shale plays-for both oil and gas-appear to be present throughout the geologic section. Here's a tour, from oldest to youngest, of several rising shale plays and the operators that are pushing them into the mainstream.



Devonian Marcellus and Huron

The Appalachian Basin's Devonian shales carry staggering gas resources. For one company alone, these shales contain trillions of cubic feet (Tcf) of reserve potential.

That company is Fort Worth-based Range Resources Corp., and it has staked a leading position in two Devonian shale plays. In Pennsylvania, the company has 420,000 acres that are prospective in the Middle Devonian Marcellus shale. In southern Appalachia, it holds another 378,000 acres that are promising in the Huron member of the Upper Devonian Ohio shale.

"In the Appalachian Basin, the Devonian shale has been recognized for a long time as commercial," says Jeff Ventura, Range executive vice president and chief operating officer. Indeed, Kentucky's Big Sandy Field, the granddaddy of shale-gas fields, will ultimately make more than 3 Tcf of gas. Big Sandy was discovered in 1914, and despite nearly 100 years of production, still makes abundant gas.

Furthermore, Appalachia is bursting with black shales. In its assessment units in the basin's Devonian shales, the U.S. Geological Survey (USGS) has estimated mean technically recoverable resources of 31.4 Tcf and 562 million barrels of gas liquids.

Pennsylvania's main shale objective is the Marcellus, a thick, organic-rich rock found at depths between 5,000 and 8,000 feet. The Marcellus is normally to slightly geopressured but is not extensively fractured. Companies tried for years to produce gas from the Marcellus, but the lack of natural fractures meant there wasn't enough permeability for commercial flow. But times-and drilling and completion technologies-have changed.

Range, which has deep roots in the Appalachian Basin, decided to focus on the shale in 2004. It selected areas in Pennsylvania that contained between 75 and 200 net feet of shale with vitrinite reflectance values between 1% and 2%, and total organic carbon (TOC) around 5%.

"We initially tried a Barnett-style slickwater frac in a vertical Marcellus well," says Ventura. That first well was quickly followed by two more. "We now have three wells that have been on production for about 18 months, and they will make on the order of 800 million cubic feet of gas each."

Since its first successes, Range has drilled another 27 vertical wells and experimented with different types of fracs and completions. Early on, it also drilled three horizontal wells. To date, it has 22 vertical and two horizontal wells on production.

Range expects that a vertical well in a development program could be drilled for approximately $900,000. "That gives us a finding cost around $1.30 per thousand cubic feet, and that's very attractive," says Ventura. Added bonuses are that the Marcellus gas is rich, about 1,200 Btu, and Range's gas from this slice of the basin fetches a premium of about 35 cents to the Nymex price.

As economic as the vertical wells appear to be, horizontal wells could potentially offer even juicier returns. Range's people think the Marcellus play will likely move to horizontal wells, but the company is fully testing both types of wells before it makes a wholesale commitment.

This year, Range plans to aggressively grow its Marcellus program. Plans are to drill about 35 vertical and 15 to 20 horizontal wells in the play, in Washington County and two other main areas. By year-end, it will have tested across most all of its 420,000 acres prospective for the shale. To support this effort, Range recently opened a regional office in Pittsburgh.

"There's a widespread area prospective for the Marcellus. Gas-in-place volumes are huge, and we're taking today's technologies and today's gas-price environment to see if we can make the play work." Unrisked reserve potential is between 2.5 and 5 Tcf, net to the company.

Range is also working the Huron shale play, in West Virginia and Virginia. This is a tiger of a different stripe: these shales are slightly younger than the Marcellus and are subnormally pressured, from 0.15 to 0.2 psi per foot at depths of 4,000 to 6,000 feet. Historically, vertical-well technologies worked just fine in the Huron in Big Sandy, thanks to abundant natural fractures.

Recently, operators Equitable Resources and Cabot Oil & Gas have been drilling horizontal Huron wells and stimulating them with multiple foam fracs. Results are promising, and interest in the Huron is surging.

Range holds 300,000 gross acres in its Nora area in western Virginia, about 10 miles east of Big Sandy. The company has 37 wells in Nora, which is mainly a coalbed-methane field, that produce from deeper commingled Devonian shale and tight sands. There's also an existing vertical well, #203 Clinchfield, that will make more than 2 billion cubic feet (Bcf) from the Huron.

Range plans to take the same style of horizontal well that Equitable has successfully drilled in the Big Sandy area and try it at Nora. Range will have all the benefit of that experience, as Equitable will be a 50% partner in the Nora test. Separately, Range also plans a horizontal well on its 80,000-acre Widen block in West Virginia. Both wells are to be drilled by year-end.

"Net to Range, the Huron play could bring us 1 to 1.5 Tcf," says Ventura. "It's a big upside."







Upper Devonian New Albany

Activity in the Illinois Basin's New Albany shale has flashed and faded during the past decade. Operators have been persistently tinkering with production methods, however, and finally appear to have cracked the nut.

The Devonian-aged shale, correlative to the Antrim in the Michigan Basin and the Huron in the Appalachian Basin, contains both biogenic and thermogenic gas. It is ubiquitous throughout the entire Illinois Basin, and companies have pursued a variety of approaches to tap the gas.

Aurora Oil & Gas Corp. has been working in the New Albany for 10 years. Initially, the Traverse City, Michigan-based company drilled 80 vertical tests in six counties in the shale, and put a 20-well pilot on production. Most of these wells were at depths of less than 1,000 feet. This was the technique that worked well in the Antrim shale, a play in which Aurora had considerable experience.

However, the company soon realized that the high-angle fractures in the New Albany were more amenable to horizontal wells than the low-angle fractures common in the Antrim. Aurora then embarked on a horizontal program, and drilled seven such tests.

In 2003, Aurora sold most of its shallow acreage and production to concentrate on a trend of highly fractured shales that occur between 1,500 and 2,500 feet. That same year, it recruited El Paso Exploration & Production Co. as a partner to target development of 100,000 acres in the center of its identified trend.

At present, Aurora has amassed 457,000 net acres in this target area, mainly in southwestern Indiana. The play also extends into Kentucky, where the shale is deeper and tends to contain thermogenic gas.

"2007 will be a very important year for the development of the New Albany shale story," says William Deneau, chief executive officer. "A year and a half ago, there were only about six companies pulling permits for New Albany shale wells. Today, there are more than 20 operators requesting permits."

For its part, Aurora plans to drill 28 net wells in Indiana's New Albany this year. "For $850,000 we believe that we can drill, complete and hook up a New Albany shale well that establishes 1.2 Bcf in reserves," he says. Fortuitously, New Albany wells produce natural gas from the get-go, along with water, and the water and gas production blow down together.

Aurora has portioned the play into areas that ring its central area of mutual interest (AMI) with El Paso, which lies in Daviess, Martin and Dubois counties. In that venture, in which Aurora has a 5% working interest, El Paso has drilled some 25 horizontal wells from 1,500 to 3,000 feet deep. Eighteen wells are currently on production. This year, the companies plan to drill another 20 wells in the AMI.

At present, most industry activity in Indiana is in counties west of the El Paso venture. This year, Aurora will drill five horizontal wells in Knox County and participate with partner Rex Energy in an additional five. To the south, Aurora plans to lay the groundwork for a 10-well pilot; to the east, it expects to drill four horizontal wells. Finally, in the northern portion of its acreage, it will drill four new wells and build facilities for a pilot unit. "We're going to be very aggressive this year. We plan to evaluate each of our lease areas."

Several different styles of horizontals are being tried in the New Albany, as operators have yet to settle on a preferred technique. Most of Aurora's upcoming wells will be medium-radius horizontals, with lateral sections between 1,000 and 5,000 feet.

Generally, wells are completed openhole and are not stimulated, although a few fracture treatments have been tried. "Certainly, the play is so vast that it's unlikely that one method will be superior everywhere," he says.

One of the benefits of the play also poses one of its drawbacks. Throughout most of Aurora's area of activity, there was little prior oil and gas drilling. Mineral estates have not been severed from surface, so the local landowners are invested in the economic success of the play. "This is a new business in these areas, and the response of the public has been very good," says Deneau.

Yet, that also means almost no infrastructure exists in the Indiana play, although some major transportation lines cross the state. To produce its horizontal wells, El Paso had to build a pipeline to the west underneath the White River to connect into a Texas Gas Transmission line. El Paso now has the only viable way to move gas out of Daviess and Martin counties.

But, those are the kinds of problems producers like to have. Where once the issue was making enough gas to justify development, access to markets is a problem that is quickly solved.

"We've been believers in the play," says Deneau. "The New Albany is already demonstrating its viability, and I think its economics will prove out very well."

Pennsylvanian Bend

A shale-gas play in the Texas Panhandle is finally at the edge of commercial production. The Lower Pennsylvanian Bend shale in the Palo Duro Basin has intrigued operators for several years, but initial results were uneven.

The play, mainly in Motley and Floyd counties, Texas, offers a number of attractive selling points. The thermally mature shale is between 500 and 1,000 feet thick and occurs at depths between 7,000 and 10,500 feet. However, TOC values range from around 2% to 4%, low compared with the gold-standard Barnett, and the Bend tends to contain more clastics than the Barnett. Water production due to mechanical failures and spotty gas rates have been issues.

Now, however, several strong well tests are signaling a breakthrough. PetroGlobe Inc., a Calgary independent, has been working the play since 2003. The company recently tested its McIntosh #1-77 in the southeastern corner of Floyd County at a preliminary absolute open-flow potential of 3.3 million cubic feet of gas per day, unstimulated. The well also tested 150 barrels of condensate per million.

Additionally, Vancouver-based Tyner Resources, one of the early movers in the Bend play, announced it achieved a steady flow that averaged 225,000 cubic feet of 1,400-Btu gas per day during a six-month production test at its R.G. Stephens well, in western Motley County. Significantly, the test was in just a small section of the shale interval.

Bankers Petroleum Ltd., another Calgary-based firm, has been working in the play for several years as well, and also announced some good news. The company recently reported after-frac flow rates of 325,000 cubic feet of gas per day from its vertical Cogdell #64-1 in Motley County. That completion was in Granite Wash sands in the lower part of the hole.

"We are looking at the whole package of sediments in the Bend group," says Wolf Regener, Camarillo, California-based president of Bankers Petroleum (US) Inc. "That includes the Granite Wash sands in the lower part and the Bend shales in the upper part." Bankers has just plugged back the sands in the Cogdell #64-1, and is now ready to stimulate the shales.

At present, Bankers holds 277,000 acres in the Palo Duro Basin. It has made two major transactions of late: it purchased Vintage Petroleum's substantial position in unconventional plays, including assets in the Palo Duro, and it separately agreed to sell approximately 100,000 acres of its Palo Duro holdings to another firm.

"There's been some real encouragement in the play recently," says Regener. "We're not quite there yet, but we're going down the road to where we need to be."

Bankers' initial efforts are directed at drilling vertical wells to depths of between 8,000 and 10,000 feet. "If a vertical well can make 100,000 to 500,000 cubic feet per day, and we can achieve some consistency and repeatability, we can start to drill horizontal wells to increase flow rates," he says.

Current costs for a Palo Duro vertical well, including larger-diameter casing and fracture treatment, are $2.2 million. The company estimates it should be able to drill and complete a horizontal test for $3 million. "Over time, we believe we can drive those costs downward."

Fewer than 20 wells have been drilled in the play by all parties, so it's undisputedly in its early stages. To date, Bankers has drilled four wells in the Palo Duro, and acquired two existing Vintage wells. It has extensive core analyses, and those data have substantiated gas contents in a prime area that range from 80 to 130 Bcf per section.

This year, in addition to stimulating the shale in the Cogdell #64-1, Bankers will drill a new vertical well and stimulate another well that has been drilled and cased. A couple of horizontal wells are also possibilities.

"We've narrowed the play down to a target area, and we're focusing on determining the best completion techniques for the shales and also for the sands," he says.



Cretaceous Mowry

The Rocky Mountain region also hosts abundant prospective shales, and an oil play that is drawing attention focuses on Wyoming's Mowry shale. Long known as an outstanding source rock, the Mowry has the added draw of a history of conventional production. Generally considered a bail-out zone, the Mowry has produced some respectable volumes of oil through the years from vertical completions.

The Mowry is a brittle, highly siliceous shale that spans an immense area, so it's not easy to characterize. Generally, TOC values range from just below 1% to a little more than 5%, and tend to increase from northwest to southeast. Thickness varies from 180 to 700 feet, and vitrinite reflectance reaches up to 1.7 at depths of more than 10,000 feet. Potential oil yields of 17 gallons per ton have been measured.







American Oil & Gas, a Denver-based independent, has been building an acreage position in Wyoming's southeastern Powder River Basin for Mowry for the past three years. Well-known Casper-based geologist Jimmy Goolsby put together the company's initial block on its Krejci prospect located in Converse and Niobrara counties.

"Dr. Goolsby had the vision on this area, and believed Krejci was the place to kick-start the Mowry play," says Pat O'Brien, chairman and chief executive officer. Goolsby positioned the prospect at the point where the basin-bounding fault makes a sharp turn from north-south to northeast-southwest. Here, thinly laminated shales and siltstones form a competent package between bentonite seals at the top and base of the Mowry.

Privately held North Finn LLC, based in Casper, was American's original partner in the deal. Austin, Texas-based Brigham Exploration Co. took a farm-out on Krejci for a partial interest in American and North Finn's acreage position and is operating the drilling program. Today, the three companies hold 120,000 gross acres in Krejci area, in which the Mowry occurs at depths of 7,500 feet and is 180 feet thick.

"We are focused along the basin-bounding fault because of the potential for natural fracturing to occur," says Andy Calerich, American's president. Auspiciously, three 1960s-vintage wells in the area were completed by Union Oil in the Mowry and together produced some 78,000 barrels of oil. "This area is compelling."

Brigham agreed to drill two horizontal Mowry wells as part of its farm-in, and those initial wells provided significant encouragement. Krejci #3-29H had a 1,600-foot lateral, and it produced an average of 160 barrels a day from 200 feet of openhole section for a period of three weeks.

The lateral in the second test, Mill Trust #1-12H, reached 1,300 feet. Casing was run to 900 feet and only the openhole section has been completed for production. The well currently produces about 20 barrels of oil per day. The 900-foot cased-hole section remains to be completed; however the partners believe that cement damages the Mowry shales, which are finicky Cretaceous rocks that contain such troublesome clays as illites and smectites.

"Our first two wells were experimental, and we tried various technologies," says Calerich. "We're turning the corner on understanding what works and what doesn't in the Mowry."

Subsequent to completions of the two earning wells, interests in the project are now 50% Brigham, 45% American and 5% North Finn. The companies changed the wellbore design for the third well, Werner #1-14H. The lateral reached 3,100 feet, and Brigham ran an uncemented preperforated liner to total depth. At present, the completion process is under way in the Werner, and a fourth well, State #1-16H, is drilling.

For the balance of the year, the partners plan an additional six wells at wide spacing across their acreage block. "We're early in the process, but we're excited about the potential," says Calerich.

The Mowry play also extends into central Wyoming's Big Horn Basin. Denver-based independent Robert L. Bayless, Producer LLC has put together 45,000 acres of long-term leases in the basin, says Matthew Silverman, exploration manager. The company's Cowboy prospect area is in the northeastern part of the basin, in Park and Big Horn counties. Lowe Partners LP is an internal partner in the acreage, which primarily consists of federal leases.

"The Big Horn is one of the oiliest basins in the Rockies, and we have identified a sweet spot for exploration for oil from the Mowry shale," says Silverman. Bayless used a variety of datasets to locate structural sweet spots in the Mowry on the Greybull Arch, a regional paleofeature. Wrench faulting along the arch contributed to intense fracturing in the easily shattered Mowry.

Depths at the Cowboy prospect range from 7,000 to 12,000 feet, and well penetrations are sparse. Nonetheless, seismic, aeromagnetic, petrophysical and geochemical data all support the potential of the shale in the area, he says.

"We think that for every 1,000 acres, we can produce at least a million barrels of oil." Estimated resource potential of the Cowboy prospect is 50 million barrels.

Bayless and Lowe are looking for an operating partner for the project. "Well costs are important, but this is still at the exploration step. We're wrestling with the appropriate well configuration-whether vertical, short-reach horizontal or long laterals will be best," says Rob Bayless Jr., executive manager. The partners hope to spud their initial well in 2008.

Miocene Monterey

The Miocene Monterey formation is a source rock familiar to any petroleum geologist working California. Furthermore, the Monterey has been well known as a productive reservoir offshore the Golden State, where it makes oil in prolific volumes from fractured cherts.

Now attention is turning to the Monterey in the San Joaquin Basin. Operators have realized that high-porosity facies within the diatomaceous shales of the Monterey can be prolific producers.

Diagenetic changes can transform portions of these shales into oil-productive reservoirs. As Monterey sediments are subjected to increased pressures and temperatures that accompany burial, they convert from opal A to opal CT and finally to quartz-phase chert. The conversion significantly alters rock properties, and changes portions of the Monterey into highly fractured and oil-saturated reservoirs.

Handily, operators have found that seismic data can detect the different Monterey facies. Amplitude anomalies are used to pinpoint the various rock types, and seismic modeling (using p-wave and converted-wave 2-D data) can discern the lateral span of reservoir facies.

Two of the great analogs for Monterey production are North Shafter and Rose fields, on the east side of the basin. These fields feature fractured quartz-phase rocks in the McClure Shale member of the Monterey formation that are trapped updip by opal CT-phase rocks, which lack permeability and have no hydrocarbon saturation.

The fields were originally discovered in 1983, but development languished until 1995. That's when several vertical wells were attempted, and results were encouraging enough to spur horizontal attempts in 1998. Today, more than 60 horizontal wells have been drilled in North Shafter and Rose fields, which together have already produced more than 9 million barrels of oil and 3.5 Bcf of gas. The two accumulations still make more than 3,000 barrels per day, plus associated gas.

According to the USGS, the siliceous rocks of the Monterey in the central San Joaquin Basin contain some 125 million barrels of undiscovered oil, distributed across many fields.

Now, independent Royale Energy Inc. plans to produce the Monterey in Rio Bravo Field, located in Kern County just four miles south of North Shafter. The San Diego-based firm is acquiring 50% of Matris Exploration Co.'s interest in Rio Bravo. The agreement gives Royale rights to develop and drill in undeveloped portions of the existing field, specifically in the shallower Monterey and also in deeper conventional reservoirs, says Stephen Hosmer, chief financial officer.

"We have watched other players in the San Joaquin making very good strides in producing oil from the Monterey in various fields," says Mo Rahman, chief geologist. "As technology has improved, people have started looking at plays that were not obvious before."

Rio Bravo is a huge old field, and has made 175 million barrels of oil and 150 Bcf of gas since its discovery in the 1950s, mainly from deeper Rio Bravo, Vedder and Olcese sands. Nonetheless, its 2,000-foot-thick Monterey section has not yet been evaluated.

The first item of work will be to test a well that Matris has already drilled. Weber #27-27 was initially a vertical hole, and then a horizontal leg was kicked off in one of the higher permeability streaks. Royale plans to test the Monterey zone by zone, to pick intervals for production, reentry or offset wells.

"Based on the results, we will extend into the rest of the acreage," says Rahman.

Royale will select a completion scheme from one of two approaches. Monterey wells in North Shafter are drilled horizontally and then fracture-stimulated, while at Elk Hills, where the formation also produces, wells are just acidized and cleaned up.

The differences stem from the varied lithologies of the Monterey. "We have zones that are dolomitic, some that are rich in forams, and zones of porcelanite, a silica-rich shale that is very brittle and highly fractured," he says. The style of laminations in the shale is another crucial factor: thin laminations are better for the propagation of artificial fractures.

At Rio Bravo, the Monterey occurs between 8,000 and 10,000 feet, and the crude gravity is in the mid- to upper 20-degree range. Royale expects high gas-to-oil ratios, and it expects to have quite a bit of water during initial production. As production proceeds and the pressure drops, the volume of oil should increase and water production decline.

"All other structures in the San Joaquin Basin have produced either from the Monterey or the time-equivalent Stevens sands," says Rahman. Until now, Rio Bravo was skipped over in the push to develop Monterey potential.

"We've been interested in this play for several years," says Hosmer. "We're very happy to have this opportunity."

Pending the results of its initial completion work, Royale plans to launch a drilling campaign during the third quarter of this year. However, it's too early to make estimates of the number of potential locations, says Hosmer. "We have to do a lot more work on the areal extent and drainage areas, and we have to produce and test the formation."

First looks will be at vertical wells, and then the company will assess the additional rate that can be added with the increased reservoir exposure in horizontal legs. Verticals might work well at Rio Bravo, as the Monterey has four or five prospective zones there, versus one productive interval in North Shafter.

Initially, vertical well costs are expected to be $1.8- to $2.5 million apiece. "Right now we're on the very steep side of the learning curve, but a great deal of information will be gathered in the coming months," says Hosmer.

"We're very excited about how this fits into Royale's strategic plan to blend more oil into our production mix, and to expand our core operations in California."

Indeed, that's the refrain from across the nation. Shale plays offer tremendous possibilities to companies large and small, in basins that have been thoroughly picked over for conventional reservoirs. Shales have been hiding in plain sight; at this moment, a happy combination of technologies and prices are bringing their potential to light.

Comments